The present invention relates to apparatus and methods for lifting liquids from a wellbore during production of gas or oil and more particularly to lifting liquids from wellbores where the natural reservoir pressure has diminished over time.
It is well known that during the production of hydrocarbons, particularly from gas wells, the accumulation of liquids, primarily water, has presented great challenges to the industry. As the liquid builds at the bottom of the well, a hydrostatic pressure head is built which can become so great as to overcome the natural pressure of the formation or reservoir below, eventually xe2x80x9ckillingxe2x80x9d the well.
A fluid effluent, including liquid and gas, flows from the formation. Liquid accumulates as a result of condensation falling out of the upwardly flowing stream of gas or from seepage from the formation itself. To further complicate the process the formation pressure typically declines over time. Once the pressure has declined sufficiently so that production has been adversely affected, or stopped entirely, the well must either be abandoned or rehabilitated. Most often the choice becomes one of economics, wherein the well is only rehabilitated if the value of the unrecovered resource is greater than the costs to recover it.
A number of techniques have been employed over the years to attempt to rehabilitate wells with diminished reservoir pressure. Some of these are using soap sticks, xe2x80x9cpittingxe2x80x9d the well occasionally by blowing the well down in a pit to atmospheric pressure, swabbing, injecting high pressure gas into the formation, lowering the end of the tubing string to the perforation, tapering the tubing string to a smaller inner diameter near the surface to increase the flow rate, optimizing tubing size to balance velocity and friction effects, waterflooding the formation to augment pressure depletion, insulating and heating the production tubing string to minimize condensation and liquid fallout and beam lifting.
One common technique has been to shut in or xe2x80x9cstop cockxe2x80x9d the well to allow the formation pressure to build over time until sufficient to lift the liquids when the well is opened again. Unfortunately, in situations where the formation pressure has declined significantly, it can take many hours to build sufficient pressure to blowdown or lift the liquids, reducing the hours of production. Applicant is aware of wells which must be shut in for 12-18 hours in order to obtain as little as 4 hours of production time before the hydrostatic head again becomes too large to allow viable production.
Two other techniques, plunger and gas lift, are commonly used to enhance production from low pressure reservoirs.
A plunger lift production system typically uses a small cylindrical plunger which travels freely between a location adjacent the formation to a location at the surface. The plunger is allowed to fall to the formation location where it remains until a valve at the surface is opened and the accumulated reservoir pressure is sufficient to lift the plunger and the load of accumulated liquid to the surface. The plunger is typically retained at the wellhead in a vertical section of pipe and associated fitting called a lubricator until such time as the flow of gas is again reduced due to liquid buildup. The valve is closed at the surface which xe2x80x9cshuts inxe2x80x9d the well. The plunger is allowed to fall to the bottom of the well again and the cycle is repeated. Shut-in times vary depending upon the natural reservoir pressure. The pressure must build sufficiently in order to achieve sufficient energy, which when released, will lift the plunger and the accumulated liquids. As natural reservoir pressure diminishes, the required shut-in times increase, again reducing production times.
Typically, a gas lift production system utilizes injection of compressed gas into production tubing to aerate the production fluids, particularly viscous crude oil, to lower the density and cause the resulting gas/oil mixture to flow more readily to the surface. The gas is typically separated from the oil at the surface, recompressed and returned to the tubing string. Gas lift methods can be continuous wherein gas is continually added to the tubing string, or gas lift can be performed periodically. In order to supply the large volumes of compressed gas required to perform conventional gas lift, large and expensive systems, requiring large amounts of energy, are required. Gas is typically added to the production tubing using gas lift valves directly tied into the production tubing or optionally, can be added via a second, injection tubing string. Complex crossover elements or multiple standing valves are required for implementations using two tubing strings, which add to the maintenance costs and associated problems.
A combination of gas lift and plunger lift technologies has been employed in which plungers are introduced into gas lift production systems to assist in lifting larger portions of the accumulated fluids. In gas lift alone, the gas propelling the liquid slug up the production tubing can penetrate through the liquid, causing a portion of the liquid to escape back down the well. Plungers have been employed to act as a barrier between the liquid slug and the gas to prevent significant fall down of the liquid. Typically, the plunger is retained at the top of the wellhead during production and then caused to fall only when the well is shut in and the while the annulus is pressurized with gas. This type of combined operation still requires that the well be shut in and production be halted each time the liquid is to be lifted.
Clearly, there is a need, in the case of wells having declining natural reservoir pressure, for apparatus and methods that would allow the energy within the annulus to be augmented for lifting the accumulated liquids in the well, without a requirement to shut in the well and halt production.
In a broad aspect of the invention, a system is provided which enables unloading or lifting of liquids from a gas well to alleviate the associated hydrostatic pressure and thus enhance gas production from a tubing string, without the need to shut-in a well. The annulus is continuously charged with compressed gas to build energy which is periodically released to lift accumulated fluids, using a combination of plunger and gas lift techniques. The wellbore annulus is fitted with a packer to create an annular chamber which can be charged with gas for creating a large pressure differential compared to that present in the reservoir alone.
A shuttle-type valve is located in the production tubing string and is positioned at the base of the wellbore adjacent the packer. The valve is operable between a production position, permitting production of fluids from the formation to the surface, and an unloading or lift position, wherein the gases within the annulus can be discharged through the tubing string, lifting any accumulated liquids to the surface.
A steady slipstream of compressed gas is continuously fed to the packed off annulus while the well continues to produce. When the pressure in the annulus reaches a predetermined threshold, a plunger, which resides in a wellhead lubricator at the surface, is triggered to fall down the tubing string and through any collected liquid. Preferably, the plunger also contacts a valve stem in the valve, actuating the valve stem to a downhole lift position. In the lift position, ports in the valve which normally allow production are blocked and the ports to the annulus are opened, permitting the accumulated pressurized gases in the annulus to vent upwardly through the production tubing, lifting the plunger and the accumulated liquid with it. The plunger is carried up the production tubing with the liquid and gases to the wellhead lubricator where it is caught and held until the unloading cycle is repeated.
The high pressure gas in the annulus vents until the pressure in the formation again exceeds that of the annulus. The higher formation pressure then acts on the valve stem to force it to an uphole production position, opening the production ports to resume production, and blocking the annulus ports so as to allow pressure to begin to accumulate in the annulus once more.
In a preferred embodiment of the invention the valve assembly further comprises a landing spring assembly which acts to xe2x80x9ccushionxe2x80x9d the impact of the plunger on the valve assembly by absorbing excess force of the falling plunger. The landing assembly comprises an outer spring to absorb the excess energy and an inner spring to accept energy transferred from the outer spring to actuate the valve stem in the valve to the downhole position.
Thus, in a broad aspect of the invention, a system is provided for enhancing gas recovery from a tubing string which extends down a wellbore into a reservoir having diminished pressure wherein the tubing string accumulates liquid, the system comprising:
a packer between the wellbore and the tubing string for forming an annulus, isolated from the reservoir;
a source to continuously build pressure within the annulus; and
a valve positioned in the tubing string adjacent the packer which is actuated, preferably using a plunger, from a production position, wherein production ports are opened and fluidly connected by a bypass chamber in the valve between the reservoir to the tubing string above the valve for producing gas from the reservoir and one or more unloading ports connecting the annulus to the tubing string are blocked, to a lift position, wherein the production ports are blocked and the unloading ports are open for releasing high pressure gas stored in the annulus to the tubing string above the valve to lift and remove accumulated liquids from the tubing string.
Preferably the valve is actuated to the lift position by the impact of a plunger falling down the tubing string and to the production position as a result of differential pressure between the vented annulus and the reservoir. Such a valve would comprise:
a tubular housing having having an upper production port fluidly connected to the tubing string above the valve, a lower production port fluidly connected to the reservoir below the valve and an unloading port fluidly connecting the isolated annulus to the tubing string above the valve; and
a valve stem having an uphole and a downhole piston and axially moveable within the housing between a first uphole production position wherein the uphole piston blocks the unloading port, the upper and lower production ports are fluidly connected and the downhole piston opens the reservoir to the lower production port, and a second downhole lift position wherein the downhole piston blocks the reservoir from the lower production port and the uphole piston opens the unloading port.
The above described valve and system enable practice of a novel process described broadly as comprising the steps of: providing a packer between the wellbore and the tubing string for forming an annulus, the annulus being isolated from the reservoir, and a valve located in a bore of the tubing string adjacent the packer; pressurizing the annulus; opening one or more production ports for fluidly connecting the reservoir to the tubing string above the valve while blocking one or more unloading ports connecting the annulus to the tubing to flow reservoir gas; and blocking the production ports and opening the unloading ports to lift accumulated liquids out of the tubing string.
Preferably, the blocking of the ports is accomplished by dropping a plunger down the tubing string so as to impact and actuate the valve from an uphole production position wherein the production ports are open and the unloading ports are blocked to a downhole lift position wherein the production ports are blocked and the unloading ports are open. The valve is preferably returned to the production position when the reservoir pressure exceeds the annulus pressure.